Production of oil and gas by CO.sub.2 miscible flooding for enhanced oil recovery can result in sour and low quality gas streams to be processed. A sour natural gas is a natural gas which contains, in addition to hydrocarbon components, one or more acid gases. An acid gas, is a gas, for example, hydrogen sulfide (H.sub.2 S) or carbon dioxide (CO.sub.2), which forms an acidic aqueous solution. Gas sweetening involves nearly complete removal of H.sub.2 S and most of the CO.sub.2 from sour natural gases. The sweetening is almost always required before the gas can meet sales gas specifications and before the sweet gas can be processed for production of ethane, propane, butane, and higher hydrocarbon liquid products.
In recent years higher crude oil prices have stimulated development of enhanced oil recovery techniques, such as CO.sub.2 miscible flooding, which can result in production of sour gas streams having a large acid gas component. In the application of CO.sub.2 miscible flooding for enhanced oil recovery, the CO.sub.2 content of the produced gas increases greatly, after breakthrough, even to levels of 98 mol % or higher. It is now apparent that processes well-adapted to the processing of high carbon dioxide content gaseous streams derived from CO.sub.2 -miscible flood produced reservoirs are highly desirable.
Cryogenic distillative processes for removing carbon dioxide from hydrocarbon containing gaseous streams have been described. Certain of these processes can include recycle of a light lean oil stream comprising, for example, C.sub.3 through C.sub.6 alkanes or mixtures thereof, to a demethanizing column to prevent carbon dioxide freeze up and/or a carbon dioxide removal column, and to prevent ethane-carbon dioxide azeotrope formation or to enhance the volatility of carbon dioxide relative to hydrogen sulfide in the carbon dioxide removal column.
FIG. 1, labeled "Background," illustrates the general background of the invention in greater detail. A wellstream 11 from a sour gas reservoir is flash separated 12 into a gaseous stream 13 and a liquid stream 14. The liquid stream 14 is stabilized 16 to lower the vapor pressure of the liquid stream, thereby producing a stabilized condensate stream 17 and a vapor fraction stream 15 which is typically combined with gaseous stream 13 for gas treatment 18. Gas treatment 18 for a stream from a typical sour gas reservoir typically employs conventional amine treating to separate an acid gas stream 19 containing predominantly H.sub.2 S and CO.sub.2 which can be further processed in a sulfur plant 20 to produce an elemental sulfur product stream 21. Gas treatment 18 also typically produces a sweet gas stream 22 which after dehydration and recovery 23 produces a sweet residue gas stream 24, a liquefied petroleum gas (LPG) stream 25, and a natural gasoline liquids (NGL) stream 26. Dotted line 27 indicates generally the functional locus of the invention herein described in detail below.